Since the enactment of the National Energy Act of 1979, many private energy producers (i.e., not owned by an electric utility) have been planning and building generation and cogeneration facilities in order to sell power to the local electric utility. Generators of this type are commonly termed as dispersed sources of generation facilities, or by the acronym DSG. Previously, the generation sources that were not owned by a utility were typically very large industrial plants with generators connected to the power system at a substation through a dedicated line. However, many of the private generators, built after 1979, are connected directly to the closest utility distribution circuit. With this configuration, the parallel generator may energize a distribution line after the utility circuit breaker or line recloser has opened, putting utility personnel and equipment at risk.
Aware of the problems associated with connecting generators in this manner, electric utilities across the United States developed a complex set of specifications and standards for protective relay systems that would allow safe and reliable interconnections of DSG to the electric utilities. These vary with the specifications of the generator, the detailed nature of the utility connection point, as well as the protection philosophy of the particular utility. These philosophies are based on the fact that the utilities must be satisfied that other customers, who are connected near the point that the private generator is connected, are protected from danger and damage to equipment that could be caused by the generator during system disturbances. One reference guide for this type of generation source is the IEEE Guide for Interfacing Dispersed Storage and Generation Facilities with Electric Utility Systems, ANSI/IEEE Std 1001-1988, The Institute of Electrical and Electronics Engineers, Inc., New York, NY, 1988.
In some cases, it is desired to operate the DSG to support the load at the site and operate as an island when not connected to the utility. Therefore, manufacturers of these generally smaller generators also needed protective relay systems that would protect their on-site equipment.
Aside from the protective functions required, many utility specifications included requirements that the relays must meet to be connected to the system; such as temperature, humidity, transient and radio frequency interference protection, as well as testing capabilities.
Most protective relays are analog devices. However, several manufacturers have developed microprocessor-based protective relays that include the tripping functions required to protect the interconnection, while others have designed protective relays for the generators. In the past to fulfill most of these requirements, at least 13 discrete relays and several associated timers necessary to protect the generator and its interconnection had to be installed at the DSG site.
The first obvious problem with this approach was designing and building the package. First the panel design, including placement of the various sizes and shapes of the relay, and the wiring between each relay, had to be considered in the overall design of the package. The various equipment then had to be purchased, often from different manufacturers, and the individual orders had to be monitored until they arrived at the job site. Acceptance tests were required to be performed on each relay to assure that they met specifications. Also engineering changes may have been required to make an individual relay suitable for the designed protection package.
Calibration of analog components, using mechanical adjustments of trimpots on the printed circuit board, was often required. The potentiometers that are used on many analog relays have an inherent error between the electrical position of the potentiometer and the slider. If these components were mounted on a printed circuit board inside the relay, calibration had to be done before initial installation, since they were inaccessible once they were mounted in a panel.
Each relay or associated component then had to be installed in the panel, which meant cutting holes for mounting each unit, and wiring between the units as well as between the panel and the associated equipment.
Once installed, the limits for each function of each relay had to be set on the front panel dials. The procedures to accomplish this often varied between each individual relay.
In analog designs, the inherent limits on accuracy for many of the components used is compounded by the limits on accuracy in calibrating the components. In addition, the settings were only as accurate as the skill of the operator to initially calibrate the knob and to align the pointer on the dial with the dial markings. Therefore, the generator and its interconnection could either be overprotected or underprotected.
Throughout its lifespan, each relay and associated component would be subjected to periodic testing, maintenance and recalibration (due to possible drift of analog components); which often had to be performed by taking the devices out of the panel. This required that the generator be disconnected from the utility; and, if the generator was required to support on-site critical loads, also left the generator unprotected during these procedures.
Another time-consuming disadvantage of using a number of relays is that different procedures had to be learned both by operators who used the equipment, and technicians who tested, repaired, calibrated and maintained the various equipment.
Another disadvantage of some analog devices is that they are not properly protected against the harsh environmental and electrical conditions found in the electric utility systems. For example, transients, extreme temperatures, humidity, radio frequency interference and dust accumulation can greatly reduce the life of many analog-based relays.
Even after the generator and its protection package is operational, system conditions or protection philosophies can change. With analog-designed relays, hardware changes would be required to update the protection package.
All of the above disadvantages greatly increase the cost of the protection package. On larger generators, this is not a significant part of the cost of the installation. However, for the smaller generators used in many DSG installations, the cost of the protection package is often a large portion--from 25% to 50%--of the cost of the installation. The economic considerations often made installing a DSG unfeasible.
The inherent limitations of analog components also effect the number of components required to measure and process the input signals. In analog relays, input signal processing requires analog circuitry for each channel to calculate input conditions, such as the voltage magnitude and phase angle; and other analog circuits for the calculation of negative sequence current, real and reactive power, and other functions. In some microprocessor-based relays, signal processing is still accomplished by analog components, with the microprocessor used only for the logic to compare the limits of each parameter to the input conditions.
It is a principal object of the present invention, herein termed Multifunction Protective Relay System or MPRS, to provide in a single module, improved convenience, reliability and accuracy of those functions needed to protect the interconnection, as well as to provide almost all of the functions needed to protect smaller plants, and a majority of those required for larger generators, such as peaking plants. Permissive relaying for reconnection is also included in the design.
Since these functions are incorporated in one unit, the panel design, purchasing and acceptance testing time is greatly reduced. Because of the relatively small size of the MPRS, much less panel space and wiring are required to mount and connect the MPRS than that required by using individual relays.
Setting the limits of each required protective function is much faster on the MPRS, since the operator learns to use one technique to use a knob (which requires no calibration since turning the knob enters a digital number) and two pushbuttons to scroll through a menu-driven display, all of which are on the front panel.
A technician can more easily learn to test, repair, calibrate and maintain the MPRS, since it is in one package, than to do the same for 13 different relays. The MPRS includes self-test and self-calibration features as part of the microprocessor design, which eliminates much of time spent in manual testing and calibration of other relays. Self-calibration of the MPRS is accomplished in the form of digital numbers, which are not subject to analog drift.
Since some functions can be enabled or disabled on the MPRS, the relay is more easily adaptable to a number of different protection schemes, requiring no hardware changes if protection philosophies change.
Rather than using analog components for input signal processing, the MPRS uses digital signal processing (DSP) technology to process the input signals before it is sent to a microprocessor (second processor), which performs the logic tasks. This technique eliminates the errors inherent in analog relays, as well as eliminating the added cost required when a combination of analog and microprocessor design is used.
The packaging of the MPRS was designed for maximum protection of the electronic components from the electrical and natural environment, which includes complete transient protection and EMI filters for reliability, thus greatly increasing the reliability of the relay.
In summary, since all functions are combined in one package, the MPRS is more convenient and economical to purchase, acceptance test, install, calibrate, set and maintain. Due to the unique microprocessor design, the MPRS is more accurate and easier to use. These advantages of the MPRS, including the great decrease in the cost that its use affords, make DSG schemes safer, more reliable and, ultimately economically feasible.